rillingformularDrilling OperationHow to Determine Mud Motor FailureMud motor failure downhole may be happened from time to time. The questions that are usually raised are things like “How do I know if the mud motor fails down hole?” and “What indications will I see that this has happened?” etc. Due to this, I would like to share my personal experience regarding mud motor failure and its symptoms.

The following signs indicate that you may be faced with downhole mud motor breakdown.Frequent Mud Motor Stall – Motor stall happens when the rotor of the mud motor has stopped moving. Typically, the motor stalls only with a high differential of pressure. However, if the motor doesn’t perform as normal, it will get stalled with by a small amount of differential pressure. For instance, a mud motor normally drills at 400 psi differential pressure, but if the motor is stalled out with only 100 psi you can suspect the problem is with the motor.Pressure fluctuation while rotating – As you know, differential pressure it a set parameter while rotating down, not based on the weight on bit (WOB). Rotating with a good mud motor won’t create pressure fluctuations, whereas a bad mud motor will show fluctuation in stand pipe pressure and you may not be able to maintain constant pressure.Abnormally high surface pressure – A stator is made of rubber. When the stator rubber is worn out and breaking into pieces, small parts of rubber can jam the flow path in the motor. This situation also results in high stand pipe pressure.Reduction in Rate of Penetration – If there are no changes in formation and drilling parameters, the decreasing in ROP (Rate of Penetration) may be caused by failure of the down hole tool. Moreover, if the tool is severely damaged, you will not be able to drill any footage.What should you do if the problem is clearly identified?The only thing you can do is pull out of the hole and change a new tool. It is almost impossible to drill with a damaged mud motor unless you only have a few feet to the well target depth.With the mentioned indicators of mud motor failure above, you should be able to identify your suspected problem and begin troubleshooting as soon as possible to minimize non-productive time on a drilling rig.

Drilling Bit Types and Drilling Bit SelectionsCurrently in the drilling industry, there are two main categories of drilling bits: rolling cutter bits and fixed cutter bits. Plus, bit sizes vary from 3-7/8 inch to 36 inches.

Rolling Cutter Bits

Rolling cutter bits, which some may also call roller cone bits or tri-cone bits, have three cones. Each cone can be rotated individually when the drill string rotates the body of the bit. The cones have roller bearings fitted at the time of assembly. The rolling cutting bits can be used to drill any formations if the proper cutter, bearing, and nozzle are selected.There are two types of rolling cutter bits which are milled-tooth bits and tungsten carbide inserts (insert bits). These bits are classified by how the teeth are manufactured:1. Milled-tooth bits

(Mill Tooth Bit)Milled-tooth bits have steel tooth cutters, which are fabricated as parts of the bit cone. The bits cut or gouge formations out when they are being rotated. The teeth vary in size and shape, depending on the formation. Teeth of the bits are different depending on formations as follows:Soft formation: The teeth should be long, slender and widely spaced. These teeth will produce freshly broken cuttings from soft formations.Hard formation: The teeth should be short and closely spaced. These teeth will produce smaller, more rounded, crushed, and ground cuttings from hard formations.2. Tungsten Carbide Insert (TCI) or Insert bits

(Tungsten Carbide Insert Bit)

Tungsten Carbide Insert (TCI) or Insert bits generally have tungsten carbide inserts (teeth) that are pressed into the bit cones. The inserts have several shapes such as long-extension shapes, round shaped inserts, etc.Teeth of the bits are different depending on the formation as follows:Soft formation: Long-extension, chisel shape insertsHard formation: Short-extension, rounded inserts

Fixed Cutter Bits

Fixed cutter bits consist of bit bodies and cutting elements integrated with the bit bodies. The fixed cutter bits are designed to excavate holes by shearing formations rather than cutting or gouging formations, such as rolling cutter bits. These bits do not have moving parts such as cones or bearings. The components of bits are composed of bit bodies fabricated from steel or tungsten carbide alloy and fixed blades integrated with abrasion-resistant cutters. The cutters in the bits that are available on the market are Polycrystalline Diamond Cutters (PDC) and natural or synthetic diamond cutters.

(PDC Bit)

(Diamond Bit)Nowadays, with the improvement that have been made in fixed cutter bit technology, the PDC bits can drill almost any kind of formations from soft to hard formation. However, if you plan to drill very hard formations, you might consider using diamond bits instead.

Universal Engineering Solution For Rig People- I Know You Would Love ItWorking on the drilling rig, you nee such a simple solution to help you through troubles which can be occurred.My friend just sent me the universal engineering solution for rig personnel…look very simple and work!!!

What do you think about it?

Break Mud Gel Strength While Tripping In HoleWhen you trip out of hole and leave drilling mud in a static condition for a period of time, mud rheology (PV, YP and gel strength) of drilling mud tends to increase. It is very important that when you trip back in hole you should break the thick mud (most people call “break the gel”).What can be happened if you don’t condition thick drilling mud while tripping back in hole?Thick drilling mud tends to consume at lot of energy to move it therefore high frictional factor is occurred that will result in excessive equivalent circulating density (ECD). If formations are not strong enough to withstand the ECD, lost circulation will be happened. The lost circulation will lead to other drilling problems such as well control and well ballooning.How can you break the gel?The follow steps are example on how can you break gel of drilling mud.• Trip in hole to the casing shoe depth• Rotate pipe slowly 10-15 sec and bring pump up slowly• Circulate bottom up at reduced speed• Trip in hole about 1/3 – 1/2 way of open hole• Rotate pipe slowly 10-15 sec and bring pump up slowly (staging up)• Circulate bottom up at reduce speed and slowly reciprocate pipe• Trip in hole to bottom• Rotate pipe slowly 10-15 sec and bring pump up slowly (staging up)• Circulate bottom up at reduce speed and slowly reciprocate pipe• Drilling ahead

In the demonstrated instruction, there are many times that you stop and condition mud which will bring mud properties back to normal.Ps, this is based on my experience you may need to adjust to suit with your drilling operation.

Underbalanced Drilling – Watch This VDO To Get Clear Idea

Underbalanced drilling is a drilling technique that hydrostatic pressure from drilling mud is less than reservoir pressure. The underbalanced drilling can be created by using low weight fluids as base oil, fresh water which has less hydrostatic pressure than the expected formation pressure. Additionally, this drilling method is achieved by using low density drilling fluids as gas, foam, combination between conversional drilling fluid and foam/air.The main advantage of Underbalanced drilling is to minimized formation damage in reservoir. With underbalanced drilling, the reservoir fluid is allowed to flow out into the well therefore the chance of mud invasion into the reservoir is minimal. Hence, the production from the well from this technique is higher than normal wells. Conversely, drilling with conventional method (overbalanced drilling) creates near wellbore damages which affect hydrocarbon production.The underbalanced drilling is often applied to horizontal drilling wells because long horizontal reservoir will not be damaged with drilling fluid. Only few inches of near wellbore damage in the horizontal section can drastically reduce the reservoir performance.This video from Shell demonstrates you regarding underbalanced drilling and there is one section showing comparison between conventional and underbalanced drilling. This short VDO will definitely give you clear picture of this technique.

Why Slug Does Not Work?Slug is typically used to push mud in the drill string down therefore pipe will dry while pulling out of hole. Dry pipe while pulling out has some advantages as minimizing crew to expose to drilling mud when breaking a connection, reducing time to handle the drill string, etc. Sometimes, even you already pump slug but you still have wet pipe instead of dry pipe. You may wonder why the slug does not work very well.

The following reasons why the slug does not do its job are as follows: • Slug volume is not enough to slug the pipe. Recommended volume is around 25- 40 bbl.• You should chase slug by pumping mud at least surface volume from mud pump to a rotary table. Otherwise, you will not get desired slug volume in the drillstring because it is still left in the surface volume.• Weight of slug is not sufficient. As a normal practice, the slug weight should have at least 2 ppg over your current mud weight.• There is something inside the drill string so the slug could not push mud in the drill string down. If you want to learn more about slug, please read the following articles:What is slug mud? How much volume and weight of slug mud should be?Barrels of slug required for desired length of dry pipe

What is slug mud? How much volume and weight of slug mud should be?Slug Mud: It is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole. Slug is used when pipe became wet while pulling out of hole.Normally, 1.5 to 2 PPG over current mud weight is a rule of thumb to decide how much weight of slug should be. For example, current mud weight is 10 PPG. Slug weight should be about 11.5 to 12 PPG.Normally, slug is pumped to push mud down approximate 200 ft (+/2 stands) and slug volume can be calculated by applying a concept of U-tube (see a figure below)

Volume of slug can be calculated by this following equation:

This equation expresses that the higher slug volume, the deeper of dry in drill pipe is met. As per the above equation, length of dry pipe can be substituted by 200 ft.In normal practice, slug volume pumped to clean drill pipe is around 15-25 bbl depending on drillpipe size. Moreover, it also depends on situations because sometime mud in annulus side may be heavier than measured MW due to cutting, drilling solid contaminated in mud, hence more slug volume is needed.

Barrels of slug required for desired length of dry pipeWhat is slug? Slug: It is heavy mud which is used to push lighter mud weight down before pulling drill pipe out of hole. Slug is used when pipe became wet while pulling out of hole.Normally, 1.5 to 2 PPG over current mud weight is a rule of thumb to decide how much weight of slug should be. For example, current mud weight is 10 PPG. Slug weight should be about 11.5 to 12 PPG. Generally, slug is pumped to push mud down approximate 200 ft and slug volume can be calculated by applying a concept of U-tube (See Figure below).

Volume of slug required for required length of dry pipe can be calculated by this following equations:Step 1: Determine hydrostatic pressure required to give desired drop inside drill pipe:Hydrostatic Pressure in psi = mud weight in ppg x 0.052 x ft of dry pipeStep 2: Determine difference in pressure gradient between slug weight and mud weight:Pressure gradient difference in psi/ft = (slug weight in ppg – mud weight in ppg) x 0.052 Step 3: Determine length of slug in drill pipe:Slug length in ft = Hydrostatic Pressure in psi (in step 1) ÷ Pressure gradient difference in psi/ft (step 2)Step 4 Slug volume required in barrels:Slug volume in barrel = Slug length in ft x drill pipe capacity in bbl/ftExample: Determine the barrels of slug required for the following:Desired length of dry pipe = 200 ftDrill pipe capacity = 0.016 bbl/ftMud weight = 10.0 ppgSlug weight = 11.5 ppgStep 1 Hydrostatic pressure required:Hydrostatic Prssure in psi = 10.0 ppg x 0.052 x 200 ftHydrostatic Prssure in psi = 104 psiStep 2 differences in pressure gradient between slug weight and mud weight:Pressure gradient difference in psi/ft = (11.5 ppg – 10.5 ppg) x 0.052Pressure gradient difference in psi/ft = 0.078 psi/ft

Step 3 length of slug in drill pipe:Slug length in ft = 104psi ÷ 0.078Slug length in ft = 1,333 ftStep 4 Slug volume required in barrels:Slug volume required = 1333 ft x 0.016 bbl/ftSlug volume required = 21.3 bblPlease find the Excel sheet for calculating barrels of slug required for desired length of dry pipe.

Backreaming practice helps smoothen the well boreby DrillingFormulas.Com on March 29, 2011While you are sliding with a motor assembly, you may consider backreaming one time at least. The reason is that you will smoothen the well bore and it will help you when you run casing/completion or when you trip back in hole with another BHA.

Image from the internetThis is the example based on my experience, I drilled a 12-1/4” section with mud motor 1.5 degree bend and I slid 30 stands without back reaming. When I finish my motor run, I circulated hole clean and pulled out of hole to change to a rotary BHA. When I tripped back in hole, I could not pass where I started sliding therefore I ended up with reaming down all the way to the previous TD. It took me 4.5 hours extra. After I learned this event, I changed my drilling practice. I back ream at least 1 times every slide I made and I rarely had the problem while running casing/completion or tripping back in hole.In my opinion, you should not use this practice if you are drilling into very soft formations because you will easily lose your angle.PS, this is my opinion based on my experience. Please ask your boss again before back reaming .

What are the differences between steering (orienting or sliding) and rotating?Steering (orienting or sliding) is drilling with mud downhole steerable mud motor. Drilling with the steerable motor does not rotate drill pipe because it uses hydraulic power to drive down hole motor and bit. Steering is used in order to control well direction.Rotating is drilling with Topdrive or rotary table and drillstring is rotated in order to gouge the hole. Rotary drilling will be used when straight hole direction is needed.Comparing between steering and rotating, steering can create dog leg more than rotating because mud motor incorporating with bend housing is designed to directionally drill to the specified direction; however, when Rotating, BHA is stiffer and has tendency to hold the direction.Rotating ROP is always faster than steering ROP by these following reasons:• Friction force exerts on stable drill string when steering is always more than rotating.• When steering, WOB is limited. Motor can be stalled or worn out if WOB excesses.• Direction of well must be controlled carefully that means well can not be drilled faster.

How to Assess Material Requirements for Drilling OperationDrilling supervisors must be responsible for assessing material requirements for the drilling operation at a drilling rig. There are several following information that can help to assess material requirement in both short time (less than 48 hrs) and long time (next 3-5 day).1. Drilling Operation Instruction: The drilling operation instruction is guidance for what operations will be happening in the future. Therefore, it will give people at the rig some ideas regarding what people will be needed.2. Drilling Operation Meeting: The operation meeting is conducted everyday in order to discuss the forward plan among team members such as drilling supervisors, a drilling contractor and service companies. This meeting helps all parties at the rig to understand what drilling activities will be performed and when the operation requires the material perform jobs.3. Forward plan sheet: The forward plan sheet contains all actions from demobilization to completion of the drilling program. It assists supervisors on the rig to estimate time for upcoming operations. Mostly, it is utilized for assessing the long time (next 3-5 days) material and people requirement.4. Area on the rig: Operation supervisors must fully understand about available space of the rig because it is a constraint about how much equipment can be store on the rig. For instant, if the rig has small area, small set of equipment must be frequently ordered. On the other hand, if the rig area is big, a lot of drilling tools can be requested and kept on the rig.5. Logistics: It is very important to know how the logistics work each area because it will help personnel on the rig know how long the equipment will be transferred from a wear house to a location after issuing the material.6. Contact Warehouse: After all required materials are assessed, drilling supervisors and a material man must contact a warehouse in order to discuss with them about what the required materials are and when they should be at the rig site.

Normally, material requirement plan must be revised everyday because sometimes drilling operation is not ongoing as plan. Therefore, some equipment must be delayed or some special equipment must be urgently requested for specific drilling operation.

Drill pipe pulled to lose hydrostatic pressureYou previously learn about hydrostatic pressure lose due to pulling out of hole . This post will use the same concept but we will determine how many feet of drill pipe pulled to lose certain amount of hydrostatic pressure in well bore.The calculations below have 2 cases of pulling out of hole, pull dry and pull wet. They are different in calculation because amount of drilling fluid out of hole is different. Please follow and understand each case of calculation.#1: How many feet of pipe pulled DRY to lose certain amount of hydrostatic pressureFeet = (hydrostatic pressure loss in psi x (casing cap in bbl/ft – pipe displacement in bbl/ft)) ÷ (mud weight in ppg x 0.052 x pipe displacement in bbl/ft)Example: Determine the FEET of dry drill pipe that must be pulled to lose the overbalance using the following data:Hydrostatic pressure loss = 200 psiCasing capacity = 0.0873 bbl/ftPipe displacement = 0.01876 bbl/ftMud weight = 12.0 ppgFt = 200 psi x (0.0873 – 0.01876) ÷ (12.0 ppg x 0.052 x 0.01876)Ft = 1171 ftYou need to pull 1171 ft of dry pipe to lose 200 psi hydrostatic pressure.#2: How many feet of pipe pulled WET to lose certain amount of hydrostatic pressureFeet = hydrostatic pressure loss in psi x (casing capacity in bbl/ft – drill pipe capacity in bbl/ft – drill pipe displacement in bbl/ft) ÷ {mud wt in ppg x 0.052 x (pipe displacement in bbl/ft + (% of volume in drill pipe out of hole ÷ 100) x pipe capacity in bbl/ft)}Example: Determine the feet of WET pipe that must be pulled to lose the overbalance using the following data:% of volume in drill pipe out of hole = 100Hydrostatic pressure loss = 200 psiCasing capacity = 0.0873 bbl/ftDrill pipe capacity = 0.01876 bbl/ftDrill pipe displacement = 0.0055 bbl/ftMud weight = 12.0 ppgFeet = 200 psi x (0.0873 – 0.01876 – 0.0055 bbl/ft) ÷ {12.0 ppg x 0.052 x (0.0055 + (100÷100) x 0.01876 bbl/ft)}Feet = 832.9 ftYou need to pull 833 ft of wet pipe to lose 200 psi hydrostatic pressure.Please find how many feet of drill pipe pulled to lose certain amount of hydrostatic pressure in well bore.

Pump Pressure and Pump Stroke Relationship

There is relationship between pump pressure and pump stroke that you really need to understand and be able to determine pump pressure after adjusting new pump stroke. There are 2 formulas used to determine pump pressure as shown in the detail below:1 st formula for estimating new circulating pressure (simple and handy for field use) New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) 2

Example: Determine the new circulating pressure, psi using the following data:Present circulating pressure = 2500 psiOld pump rate = 40 spmNew pump rate = 25 spmNew circulating pressure in psi = 2500 psi x (25 spm ÷ 40 spm) 2

New circulating pressure = 976.6 psi2nd formula for estimating new circulating pressure (more complex)For the 1st formula, the factor “2” is used but it’s just the round up figure. If you want more accurate figure, you need to figure out an exact figure. So the 2nd formula has one additional formula to calculate the factor based on 2 pressure readings at different pump rate. Please follow these steps to determine new circulating pressure1. Determine the factor ”n” and the formula to determine factor “n” is below:Factor (n) = log (pressure 1 ÷ pressure 2) ÷ log (pump rate 1÷pump rate 2)2. Determine new circulating pressure with this following formula.New circulating pressure in psi = present circulating pressure in psi x (new pump rate in spm ÷ old pump rate in spm) n

Note: factor “n” comes from the first step of calculation.Example: Determine the factor “n” from 2 pump pressure readingPressure 1 = 2700 psi at 320 gpmPressure 2 = 500 psi at 130 gpmFactor (n) = log (2700 psi ÷ 500 psi) ÷ log (320 gpm ÷ 130 gpm)Factor (n) = 1.872Example: Determine new circulating pressure by using these following information and the factor “n” from above example:Present circulating pressure = 2500 psiOld pump rate = 40 spmNew pump rate = 25 spmNew circulating pressure, psi = 2500 psi x (25 spm ÷ 40 spm) 1.872

New circulating pressure = 1037 psiPlease find the Excel sheet used to calculate new circulating pressure based on pump pressure and pump stroke relationship.

System Constrain for Drilling HydraulicsWhen we get the optimum flow rate which match your optimization objective, you must check the system constrains such as• Deliverability of mud pumps is enough, isn’t it?• The optimum flow rate is within the operating range of down hole tools, isn’t it?• The maximum annular velocity is exceeded, isn’t it?• The equivalent circulating density can cause formation fracture, can’t it?

• The flow rate is below the critical flow rate, isn’t it?In the following articles, we will have more in depth details regarding system constrains for drilling hydraulics. The topics that we will discuss are as follows:• Annular velocity and its importance on drilling hydraulics• Power Law constant determination• Effective viscosity• Reynolds number• Flow regime and critical Reynolds numbers• Critical flow rateWe also have an intention to demonstrate step-by-step calculation to show you all calculation because only equations are not good enough to get all the pictures.

Mud Gas Separator

Mud Gas Separator capable of handling 1000-1500gpm

Process Flow Diagram For Mud Gas Separator

Mud Gas Separator is commonly called a gas-buster or poor boy degasser. It captures and separates large volume of free gas within the drilling fluid. If there is a "KICK" situation, this vessel separates the mud and the gas by allowing it to flow over baffle plates. The gas then is forced to flow through a line and vent it to a flare. A "KICK" situation happens when the annular hydrostatic pressure in a drilling well temporarily (and usually relatively suddenly) falls below that of the formation, or pore, pressure in a permeable section downhole, and before control of the situation is lost.It is always safe to design the mud/gas separator that will handle the maximum possible gas flow that can occur.[1][2]

Contents

• 1 Types of Mud/Gas Separators • 2 Principle of operation • 3 See also • 4 Notes

Types of Mud/Gas Separators

The principle of mud/gas separation for different types of vessels is the same.[3]

• Closed bottom type• Open bottom type• Float type

According to pedestal or base type there are• Fixed type• Elevating type

Poor boy degasser in China is usually named according to vessel diameter.So the type also including

• FLQ800 or ZYQ800

• FLQ1000• FLQ1200• FLQ1400

Usually, the degasser type or configuration is customizable

Principle of operation

The principle behind the mud gas separator is relatively simple. On the figure, the mud and gas mixture is fed at the inlet allowing it to impinge on a series of baffles designed to separate gas and mud. The free gas then is moved into the flare line to reduce the threat of toxic and hazardous gases and the mud then discharges to the shale shaker and to the tank.

The Difference between Vacuum Degasser and Poor Boy Degasser

Vacuum degasser and poor boy degasser is both are degasser in oilfield, there are some differences some maybe confused.

How do the two degasser works and the difference

This two pictures is the different work

principle of the two digassers.

The right side is the vacuum degasser, and the left side is the mud gas separator(poor boy degasser).The vacuum degasser suck the drilling mud and separated mud and gas by vacuum pump.Our vacuum degasser operates on a “thin strata” principle. The drill mud enters the tank and forces it to flow and distributed to a layer of internal baffle plates engineered to allow the liquid inside the vacuum degasser to flow as thin film and is exposed to the vacuum within the vessel. This layer of mud allows the gas to escape or break out of the mud . The vacuum pump releases the gas and discharge it to the disposal line. Mud exits the vessel under the action of the venturi and is returned to the mud system.The poor boy worked by the physical characters.The GN MUD/GAS SEPARATOR (poor boy degasser) consists of a cylindrical pressure vessel in a fixed vertical position. Inside is a series of specially angled baffle plates, stepped from the top to the bottom. When contaminated mud is routed into the separator, it flows downward successively over each plate. During this process, the heads of entrained gases “break out.” The released gas is then carried by the vent lines to a remote location where it can be safely flared.The flow of liquid from the vessel can be regulated by a liquid-level-control valve or a U-tube, ensuring adequate retention time in the separator for the gas to break out.

Mud Gas Separator Poor Boy Degasser

From: http://www.netwasgroup.com/well-control/mud-gas-separator-poor-boy-degasser.html

Tue, 15 Mar 2011 04:53:40 | Well Control

• Blood Pressure Reduction Guide • Cure For Virtually All Diseases The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. As the mud and gas mixture enters the separator, the operating pressure is atmospheric plus pressure due to friction in the gas vent line. The vertical distance for the inlet to the static fluid level allows time for additional gas break-out and provides an allowance for the fluid to rise somewhat during the operation to overcome friction loss in the mud outlet lines. As shown in Figure 39, the gas-fluid inlet should be located approximately at the midpoint of the vertical height. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention. The 30 in. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. The separator inlet should have at least the same ID as the largest line from the choke manifold which is usually 4 in. Some separators use tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture which causes faster gas break-out.The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. It is important that each plate be securely welded to the body of the separator with angle braces.

A 8 in. minimum ID gas outlet is usually recommended to allow a large volume of low pressure gas to be released from the separator with minimum restriction. Care should be taken to ensure minimum back pressure in the vent line,. On most offshore rigs, the vent line is extended straight up and supported to a derrick leg. The ideal line would be restricted to 30 ft in length and top of the line should be bent outward about 30 degrees to direct gas flow away from the rig floor. If it is intended that the gas should be flared, flame arresters should be installed at the discharge end of the vent line.As stated previously, when the gas pressure in the separator exceeds the hydrostatic head of the mud in the U-tube, the fluid seal in the bottom is lost and gas starts flowing into the mud system. The mud outlet downstream of the U-tube should be designed to maintain a minimum vessel fluid level of approximately 3 1/2 ft in a 16 ft high separator. Assuming a 9.8 ppg mud and total U-tube height of 10 ft the fluid seal would have a Well Control" href="/well-control-2/hydrostatic-pressure.html">hydrostatic pressure equal to 5.096 psi. This points out the importance for providing a large diameter gas vent line with the fewest possible turns to minimise line frictional losses.The mud outlet line must be designed to handle viscous, contaminated mud returns. As shown in Figure 39 an 8 in. line is recommended to minimise frictional losses. This line is recommended to minimise frictional losses. The line usually discharges into the mud ditch in order that good mud can be directed over the shakers and untreatable mud routed to the waste pit.During well control operations, the main purpose of a mud gas separator is to vent the gas and save the drilling fluid. This is important not only economic reasons, but also to minimise the risk of circulating out a gas kick without having to shut down to mix additional mud volume. In some situations the amount of mud lost can be critical when surface volume is marginal and on-site mud supplies are limited. When a gas kick is properly shut in and circulated out, the mud gas separator should be capable of saving most of the mud.□ rilling S Well Services TrainingThere are a number of design features which affect the volume of gas and fluid that the separator can safely handle. For production operations, gas oil separators can be sized and internally designed to efficiently separate gas from the fluid. This is possible because the fluid and gas characteristics are known and design flow rates can be readily established. It is apparent that 'gas busters' for drilling rigs cannot be designed on the same basis since the properties of circulated fluids from gas are unpredictable and a wide range of mixing conditions occur downhole. In addition, mud rheological properties vary widely and have a strong effect on gas environment. For both practical and cost reasons, rig mud gas separators are not designed for maximum possible gas release rates which might be needed; however, they should not handle most kicks when recommended shut-in procedures and well control practises are followed. When gas low rates exceed the separator capacity, the flow must be bypassed around the separator directly to the flare line. This will prevent the hazardous situation of blowing the liquid from the bottom of the separator and discharging gas into the mud system.Figure 39 illustrates the basic design features for atmospheric mud gas separators. Since most drilling rigs have their own separator designs, the Drilling Supervisor must analyse and compare the contractor's equipment with the recommended design to ensure the essential requirements are met.The atmospheric type separator operates on the gravity or hydrostatic pressure principle. The essential design features are:

• Height and diameter of separator

• Internal baffle arrangement to assist in additional gas break-out• Diameter and length of gas outlet• A target plate to minimise erosion where inlet mud gas mixture contacts the internal wall

of the separator, which provides a method of inspecting plate wear• A U-tube arrangement properly sized to maintain fluid head in the separator.

Figure 39 - Mud Gas Separator

Different Style and Different Looking

Here we set a few pictures to state this point. Maybe that sounds more.

Different Structure and Different Function

The mud gas separator is used before shale shaker, while the vacuum degasser is used after the shale shaker, so they have different function. The poor boy degasser usually used to separate the most dangerous gas, and the vacuum degasser is used only when we need more effective and more efficient results.